System and process for secondary hydrocarbon recovery

ABSTRACT

A hydrocarbon reservoir undergoing secondary recovery is subject to a first and then at least a second gravity gradient survey in which a gravity gradiometer takes gradient measurements on the surface above the reservoir to define successive data sets. The differences between the first and subsequent gravity gradient survey yields information as to sub-surface density changes consequent to displacement of the hydrocarbon and the replacement thereof by the driveout fluid including the position, morphology, and velocity of the interface between the hydrocarbon to be recovered and the driveout fluid.

CROSS REFERENCE TO PROVISIONAL PATENT APPLICATIONS

This application claims the benefit of the filing dates of and is acontinuation of U.S. patent application Ser. No. 09/309,508, filed May11, 1999 and issuing as U.S. Pat. No. 6,152,226, U.S. Provisional PatentApplications No. 60/085,059 filed May 12, 1998, No. 60/109,138 filedNov. 18, 1998, No. 60/107,329 filed Nov. 6, 1998, No. 60/107,366 filedNov. 6, 1998, and No. 60/099,937 filed Sept. 11, 1998; the respectivedisclosures of which are incorporated herein by reference.

BACKGROUND OF THE INVENTION

The present invention relates to a system and process for secondary oilrecovery and, more particularly, to a system and process for secondaryoil recovery in which the sub-surface boundary or interface between theto-be-recovered oil and the reservoir drive fluid is detected andcontrolled to optimize recovery, and, still more particularly, to asystem and process in which anomalies within the gravitation fieldcaused by density changes and contrasts consequent to the movement overtime of the sub-surface boundary between the to-be-recovered oil and thereservoir drive-out or re-pressurizing fluid is monitored.

Oil and natural gas hydrocarbon reservoirs form as a consequence of thetransformation of organic matter into various types of hydrocarbonmaterials, including coals, tars, oils, and natural gas. It is believedthat oil and gas reservoirs form as lighter hydrocarbon moleculespercolate toward the surface of the earth until they are trapped in arelatively permeable layer beneath a relatively impermeable layer that‘caps’ the permeable layer. The lighter hydrocarbon molecules continueaccumulating, often accompanied by water molecules, into relativelylarge sub-surface reservoirs. Since the reservoirs exist at variousdepths within the earth, they are often under substantial geostaticpressure.

Hydrocarbon resources have been extracted from surface and sub-surfacedeposits by the mining of solid resources (coal and tars) and by pumpingor otherwise removing natural gas and liquid oil from naturallyoccurring sub-surface deposits.

In the last century, natural gas and oil have been extracted by drillinga borehole into the sub-surface reservoirs. In general, most reservoirswere naturally pressurized by the presence of free natural gas thataccumulated above the liquid oil layer and, often, by water thataccumulated below the liquid oil layer. Since naturally occurring crudeoil has a density lower than that of water (i.e., ranging from 0.7 inthe case of ‘light’ crude oil to 0.9 in the case of ‘heavy’ crude oil),crude oil accumulates above the water-permeated layer and below thegas-permeated layer. Thus, a borehole terminating within theoil-permeated layer would yield oil that receives its driveout energyfrom an overlying gas-permeated layer and/or an underlyingwater-permeated layer.

In general, the ‘primary’ recovery of crude oil occurs during thatperiod of time that the natural pressurization of a reservoir causes thecrude oil to be driven upwardly through the well bore. At some point inthe operating life of the reservoir, the naturally occurringpressurization is effectively depleted. Several different methods, knowngenerally as secondary recovery methods, have been developed to extractcrude oil after natural pressurization is exhausted. In general,secondary recovery involves re-pressurizing the reservoir with a fluid(i.e., a liquid or a gas) to lower the oil viscosity and/or drive theremaining crude oil in the oil-permeated layer to the surface throughone or more wells. The drive fluid is introduced into the reservoir byinjection wells which pump the pressurized drive fluid into thereservoir to displace and thereby drive the oil toward and to theproducing wells.

Various schemes have been developed for the placement of the injectionswells. For example, a line of injection wells can be placed at oradjacent to a known boundary of the reservoir to drive crude oil towardand to the producing wells. As the boundary between the pressurizingfluid advances past the producing wells, those producing wells can becapped or, if desired, converted to injection wells. In anotherarrangement, injection wells are interspersed between production wellsto drive the oil in the oil-permeated layer away from the injectionpoint toward and to immediately adjacent producing wells.

Various fluids, including water at various temperatures, steam, carbondioxide, and nitrogen, have been used to effect the re-pressurization ofthe reservoir and the displacement of the desired crude oil from itsrock or sand matrix toward the production wells.

In the waterflood technique, water at ambient temperature is injectedinto a reservoir to drive the oil toward and to the producing wells. Theinjected water accumulates beneath the crude oil and, in effect, floatsthe lighter density crude oil upwardly toward and to the borehole of theproducing well. In those cases where the oil-permeated layer isrelatively thin from a geological perspective and is also confinedbetween two relatively less permeable layers (i.e., an impermeablereservoir ceiling and a more permeable reservoir basement), water isinjected at a relatively high pressure and volume to effect an ‘edgedrive’ by which the crude oil is pushed toward the oil producing wells.Sometimes, the injected water is heated to assist in lowering theviscosity of the oil and thereby assist in displacing the crude oil fromthe pores of the permeable sand or rock. The waterflood technique isalso well-suited for driving natural gas entrapped within the pores ofrelatively low-permeability rock to a producing well.

In the steamflood technique, steam is used to displace or drive oil fromthe oil bearing sand or rock toward and to the producing wells. Thesteam, which may initially be superheated, is injected into theoil-permeated layer to cause a re-pressurization of the reservoir. Asthe steam moves away from its initial injection point, its temperaturedrops and the quality of the steam decreases with the steam eventuallycondensing into a hot water layer. Additionally, some of the lighterhydrocarbons may be distilled out of the crude oil as it undergoesdisplacement at the interface between the steam/hot water and the crudeoil. The steam injection can be continuous or on an intermittentstart-and-stop basis.

In addition to the use of water and steam to effect reservoirre-pressurization and the driveout of the crude oil toward theproduction wells, carbon dioxide and nitrogen have also been used forthe same purpose.

One problem associated with water, steam, or gas driveout techniques isthe identification of the boundary or interface between the driveoutfluid and the crude oil. In an optimum situation, the boundary betweenthe driveout fluid and the to-be-displaced crude oil would move in apredictable manner through the reservoir from the injection points tothe production wells to maximize the production of crude oil. Thegeology of a reservoir is generally complex and non-homogeneous andoften contains regions or zones of relatively higher permeability sandor rock; these higher permeability zones can function as low-impedancepathways for the pressurized driveout fluid. The pressurized driveoutfluid sometimes forms low-impedance channels, known as ‘theft’ zones,through which the pressurized fluid “punches through” to a producingwell to thereby greatly decrease the recovery efficiency.

The ability to identify the position of and the often indistinctinterface or boundary between the to-be-displaced crude oil and thepressurized driveout fluid, to track the velocity and morphology of thatboundary, and to effect control thereof would substantially enhancesecondary oil recovery.

Various techniques have been developed for gaining an understanding ofthe configuration of the sub-surface geology of an oil-containingreservoir. The dominant technique involves seismic echoing in which apressure wave is directed downwardly into the sub-surface strata. Theinitial interrogation wave energy is typically created by the detonationof explosives or by specialized earth-impacting machines. Theinterrogation wave radiates from its source point with its transmissionvelocity affected by the elastic modulus and density of the materialthrough which it passes. As with all wave energy, the interrogation waveis subject to reflection, refraction, scattering, absorption, anddampening effects caused by the material through which it passes andfrom which it is reflected. The reflected wave energy is detected bygeophones spaced from the seismic source point and subjected toprocessing to yield a model of the reservoir. This technique is highlydeveloped and well-suited for detecting sub-surface structures that maybe favorable to the accumulation of oil or gas.

Other techniques for investigating sub-surface geology include the useof gravimeters to detect minute changes in the magnitude of the gravityvector for the purpose of detecting sub-surface structures that may befavorable to the accumulation of oil or gas.

The various devices and techniques used to interrogate sub-surfacestrata have led to significant advances in the ability to create a3-dimensional model or simulation of the reservoir. However, existingsensing technologies are unable to detect the location and morphology ofthe boundary or interface between the pressurized driveout fluid and theoil or natural gas in those reservoirs undergoing secondary recovery.Information as to the position, morphology, and velocity of the boundarywould be of substantial value in optimizing recovery of the hydrocarbonsundergoing recovery, especially in efficient utilization of the driveoutfluids.

SUMMARY OF THE INVENTION

In view of the above, it is an object of the present invention, amongothers, to provide a system and process for improving the recovery offluid hydrocarbons, such as oil and natural gas, from an oil and/or gasreservoir in which the reservoir is undergoing re-pressurization.

It is another object of the present invention to provide a system andprocess for secondary hydrocarbon recovery in which a pressurized fluidis used to drive oil and/or natural gas from the reservoir to aproducing well.

It is still another object of the present invention to provide a systemand process for secondary oil recovery in which the boundary orinterface between the to-be-recovered oil and a pressurized fluiddriving the to-be-recovered oil can be identified.

It is a further object of the present invention to provide a system andprocess for secondary hydrocarbon recovery in which the boundary orinterface between the to-be-recovered hydrocarbon and a pressurizedfluid driving the hydrocarbon can be identified and subsequentlycontrolled to maximize recovery.

In view of these objectives, and others, the present invention providesa system and process for secondary oil or gas recovery in which areservoir is pressurized with a driveout liquid or gas and the boundaryor interface between the driveout fluid and the to-be-displacedhydrocarbon material is monitored over time by sensing the changes indensity across the boundary with a gravity gradiometer. Sensed changesin the position, extent, velocity, and morphology of the boundary,including the formation of incipient theft zones, allow for control ofthe injected driveout fluid to optimize recovery efficiency.

A hydrocarbon reservoir undergoing secondary recovery is subject to aninitial gravity gradient survey during which a gravity gradiometer takesgradient measurements on the surface above the reservoir to define aninitial data set. At some time in the future, a second gravity gradientsurvey is conducted to provide a second data set. Differences betweenthe first and second data set yield information as to sub-surfacedensity changes associated volt displacement of the gas or oil and thereplacement thereof by the driveout fluid. Subsequent gravity gradientsurveys similarly displaced in time during the injection of the driveoutfluid yield additional information as to the position, morphology, andvelocity of the interface allowing an oil field manager to control thenumber of injection sites and the temperature, pressure, and volume ofinjected fluid to thus optimize recovery efficiency. The manager canalso determine the desirability of drilling new wells, their locations,their segmenting, and desirable orientations of each segment.

In the preferred implementation of the invention, a plurality of gravitygradient measurement stations are established on the surface above anoil or gas reservoir undergoing secondary recovery. A gravity gradientmeasuring instrument, for example, of the rotating accelerometer type,is positioned at each station in seriatim and data indicative of thegravity gradient at each station is taken to provide a first data set.This first data set yields data constituting baseline information as tothe gravity gradient over the reservoir as affected by surface andsub-surface density variations, including the gravity-affecting densitycontrast at the interface between the driveout fluid and the oil or gasundergoing displacement during the time that the measurements are beingtaken. At some time subsequent to the measurements that yielded thefirst data set, i.e., a period of time measured in months or years, themeasurements are repeated to yield a second data set. Common databetween the first and second data sets are indicative of fixed,substantially invariant data representative of the effect on the gravitygradient of the surface and sub-surface geology while non-common databetween the first and second data sets is indicative of a time-dependentchange in the gravity gradient consequent to movement over time of theinterface between the driveout fluid and the displaced oil or gas andpossible geologic noise effects.

After mitigating geologic noise effects, information as to the movementof the interface or boundary is used by an oil field manager to controlthe number of injection points including volume, pressures, andtemperatures to control and improve hydrocarbon recovery.

A particular advantage of the present invention is that the necessity ofdealing with invariant common data is substantially eliminated. Only thedifferences between subsequent sets of data, i.e., the time-lapsegradient data, need to be interpreted in terms of the position of theinterface between the driveout fluid and the hydrocarbons undergoingdisplacement, or, more generally, in terms of the change in thesaturation of the various materials in the pore spaces of the reservoirrocks.

An additional advantage of the present invention is that the inherentambiguity of obtaining sub-surface density information from gradientdata is reduced because of the knowledge that the density changes aretaking place in only those parts of the sub-surface in which driveoutfluids are being injected.

The present invention advantageously provides a system and process forsecondary oil recovery that allows observation via measurement ofgravity gradients associated with the boundary between the driveoutfluid and the to-be-recovered hydrocarbon material in such a manner thatrecovery efficiency can be optimized.

Other objectives and further scope of applicability of the presentinvention will become apparent from the detailed description to follow,taken in conjunction with the accompanying drawings, in which like partsare designated by like reference characters.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a representative cross-sectional view of a oil-producing trapor reservoir undergoing secondary recovery showing the interface betweenthe driveout fluid and the to-be-displaced oil in an idealized fashion;

FIG. 1A is an idealized graphical representation of the interfacebetween the driveout fluid and the to-be-displaced oil;

FIG. 1B is an idealized representation of the density contrast at theinterface of FIG. 1A;

FIG. 2 is a top view of the reservoir of FIG. 1 showing an oil boundaryas a stippled band in the context of a direct-line drive configuration;

FIG. 3 is the view of FIG. 2 showing the oil boundary displaced from theposition shown in FIG. 2;

FIG. 4 is an example of a five-spot recovery configuration;

FIG. 5 illustrates the manner by which a uniform gravity field isperturbed by a mass;

FIG. 5A is a top view of the field of FIG. 5;

FIG. 6 is an isometric view of a preferred gravity gradiometer withselected portions thereof broken away for reasons of clarity;

FIG. 7 is a functional block diagram showing the manner by which theaccelerometer output of the gravity gradiometer of FIG. 6 is processed;

FIG. 8 presents the mathematical derivation for a device-specificprotocol for the cancellation of instrument biases and self-gradients;

FIG. 9 presents the mathematical derivation for a device-specificprotocol to both eliminate horizontal gradients from the curvaturegradient estimates and to estimate the horizontal gradients, bothcombined with canceling instrument bias and self-gradients;

FIGS. 10A and 10B are a flow diagram of a test protocol for obtainingplural data sets; and

FIG. 11 is a graphical representation of gradient values at aninterface.

DESCRIPTION OF THE PREFERRED EMBODIMENT

An idealized and exemplary geologic formation having an oil containingstrata is shown in FIG. 1. As shown, an oil-permeated layer 10 isbounded on the top by a relatively impermeable ceiling layer 12 (knownas a “seal”) and on the bottom by a relatively permeable layer 14. Theoil-permeated layer 10 is typically a fine-grain or coarse-grain sandthat is permeated by crude oil that typically accumulates between theparticles. In a typical formation, the layers can form a shallow dome oranticline under which the oil accumulates; the oil is often accompaniedby natural gas and water. In those reservoirs that include natural gas,oil, and water, the natural gas tends to form a layer or region abovethe oil while the water tends to form a layer or region below the oil.Depending upon the geostatic pressure in the oil-permeated layer, aportion of the gas may go into solution with oil. In general, theinterfacial boundaries are typically indistinct, although, in somecases, the boundaries can be geologically distinct.

As shown on the left in FIG. 1, the layers are shifted in a verticaldirection along a fault line 16 so that a shifted rock layer 14 createsa plug 18 that defines a lateral boundary of the oil-permeated layer 10.In a similar manner, the sidewall of a salt dome 20, often found inassociation with oil layers, defines another lateral boundary of theoil-permeated layer 10. In general, the laterally bounded oil-permeatedlayer 10 confined beneath the ceiling rock is defined as a reservoir andmay occur at depths of several tens to several thousand feet below thesurface of the earth. The representation of FIG. 1 illustrates areservoir at a depth of several hundred feet and is merely exemplary ofthe large variety of geological configurations in which oil reservoirshave been found.

In FIG. 1, four derricks are presented, each with a borehole thatpenetrates through the several strata into the oil-permeated layer 10.When a naturally pressurized oil reservoir is initially penetrated by aborehole, the oil is driven through the borehole to the surface. Intime, however, the pressure in the reservoir decreases to the pointwhere mass transport to the surface ceases or drops to an unacceptableflow rate. At this point, oil flow can be induced using pumps at thesurface to extract oil or through repressurization of the reservoir byinjecting water, steam, or a gas (i.e., carbon dioxide or nitrogen) intothe reservoir through injection wells. In the example of FIG. 1, the twowells on the left are injection wells injecting a repressurizing fluidinto the oil bearing layer 10 while the two wells to the right areproduction wells through which crude oil is removed. The fully blackportion of the oil-permeated layer on the right represents availablecrude oil while the stippled portion of the layer on the left representsthat portion of the layer 10 in which the oil has been displaced andreplaced by the injected driveout fluid.

In FIG. 1, the transition from the stippled area to the black arearepresents the interfacial boundary or “front” between the pressurizeddriveout fluid advancing from the left and the crude oil being displacedthereby to the right toward the production wells. FIG. 1A is anidealized representation of the transition between the driveout fluidand the to-be-displaced oil and illustrates a physical phenomenon thatis not fully understood and which may include variables or features notshown. Assuming that the oil-permeated layer is fully saturated with oiland in the case where the driveout fluid is steam, the steam, which mayinitially be superheated, undergoes a reduction in temperature as itmoves away from the injection point and yields its latent heat. At somepoint, the quality of the steam decreases (i.e., the water contentincreases) while the heat of vaporization is transferred to thesurrounding oil. At this point, steam and/or heated condensed water mayundergo forced mixing with the oil and steam-induced fractionaldistillation may occur, during which some of the light hydrocarbons inthe to-be-displaced oil are vaporized to mix with the steam. At somepoint in the process, steam quality drops to zero or near zero (i.e.,the steam condenses to hot water). In FIG. 1A, the gradually denserstippling from the left to the right represents the displacement of theoil from its pores. In general, that about 90% of the oil is displacedfrom any arbitrarily defined volume unit with 10% of the oil remainingas residual oil; the remaining volume is typically replaced with 30%steam and 60% by water. In FIG. 1A, the steam is shown as overcuttingthe oil, since steam tends to rise within the oil-permeated layer. Theboundary is often indistinct and its morphology may change as a resultof water mixed in the lower portions of the oil-permeated layer andnatural gas in the upper portion of the oil-permeated layer.

While the example of FIG. 1 shows the secondary recovery of crude oil,the same configuration exists for the secondary recovery of natural gasretained within the pores of the gas permeated layer. In the case wherethe reservoir of FIG. 1 is a gas trap, the injected fluid (typically,water) would effect displacement of the entrapped natural gas toward andto the producing wells.

FIG. 2 is a plan view of the field of FIG. 1 showing a rectangular arrayof sixteen wells located at the center of defined blocks identified withrow and column numbers. The marking 22 at the lower portion of FIG. 2represents the location of the sub-surface fault line 16 of FIG. 1 andthe curvilinear marking 24 at the upper portion of FIG. 2 represents theoutline of the periphery of the salt dome 20 of FIG. 1. In FIG. 2, thewells in blocks 11, 12, 13, and 14 are injection wells injecting adriveout fluid into the oil-permeated layer 10 while the remaining wellsare conventional oil output wells. The stippled zone passing partiallythrough blocks 21 and 11 and completely through blocks 12, 13 and 14from the left to the right in FIG. 2 represents the position of thesub-surface edge between the oil and the pressurized driveout fluid. Ascan be appreciated, the boundary or “front” is indistinct andnonuniform, reflecting the variations in permeability of theoil-permeated layer 10. In general, the boundary will move with timeacross the field away from the injection wells toward the producingwells.

The configuration of FIG. 2 is known as a direct line-driveconfiguration since a line of injection wells in blocks 11, 12, 13, and14 pumps the driveout fluid into the oil-permeated layer. Alternativeconfigurations include the placement of the injection wells betweenproducing wells as shown, for example, by the 5-spot configuration ofFIG. 4. In the 5-spot configuration, an injection well is placed at thecenter of an array of four producing wells. The centrally locatedinjection well injects the driveout fluid to create a sub-surfaceboundary that extends around the injection well to sweep, displace, ordrive the oil towards and to the production wells. Variations of the5-spot configuration include the 7-spot and the 9-spot configurations(not shown) in which the centrally located injection well is surroundedby seven and nine production wells respectively.

FIG. 3 is a representation of the field of FIG. 2 displaced in time toshow the migration of the boundary between the driveout fluid and theto-be-displaced oil over a period of time. In general, the timedifference between FIG. 2 and FIG. 3 can be measured in weeks, months,or years, depending upon the size of the reservoir involved and theinjection and production rates. As shown, the boundary moved furtheraway from the injection wells with different portions of the frontmoving at different velocities to substantially change the morphology ofthe boundary. More specifically, the boundary at the left has moved pastthe wells in blocks 21 and 31 while the boundary at the right has movedonly past the well in block 24. Additionally, a portion of the boundarybetween the wells in blocks 22 and 23 has moved into and toward the wellin block 33. The particular morphology shown between the wells in blocks22 and 23 into block 33 is highly suggestive of a theft zone, i.e., avolume of relatively higher permeability material that allows thepressurized driveout fluid to form a channel therethrough that can punchthrough to a producing well and substantially reduce recoveryefficiency.

Information as to the position, extent, morphology, and velocity of theboundary with time would be valuable in managing the injection wells tooptimize the area swept by the moving boundary and thus optimizerecovery. Information relating to changes with time of the oil layer isuseful in predicting depletion trends, identifying the location andextent of remaining resources, and provides information as to placementof new injection and production wells to optimally increase yield.

In the context of FIG. 1A, the density of an arbitrary volume unit is afunction of the density of the liquid and gas fluids, the liquid and gasfluid saturations, the density of the rock matrix, and the porosity ofthe rock. The change in density Δρ for a reservoir volume unit ΔV can berepresented as:

 Δρ=P(ρ_(f)Δ_(f)+ρ_(g)Δ_(g))

where ρ_(f) is the density of the liquid, Δ_(f) is the change in liquidsaturation, ρ_(g) is the density of the gas, and Δ_(g) is the change ingas saturation.

In general, the rock has a typical density of between about 1.9 and 3.0g/cm³ and the oil has a density of between 0.7 g/cm³ in the case oflight oil and 0.9 g/cm³ in the case of heavier oil; accordingly, theoil-permeated material can be viewed as having a composite density. Asthe driveout fluid displaces and replaces the trapped oil, the compositedensity changes as a consequence of the displacement of the oil and theoccupation of the pores by residual oil and the driveout material. Inthe case of an arbitrary volume unit at point “A” in FIG. 1A, thedensity is a function of the rock matrix, the residual oil (about 10%)and the newly introduced steam (about 30%) and water (about 60%). Thus,the density difference between volume units at point “A” and at point“B” in FIG. 1A represents a density contrast that will affect the localgravity gradient in such a way that changes in that gradient can beascertained on the surface. In general, the density contrast will beless than a few tenths of a gram/cm³; the lateral dimension of thetransition zone across which the density contract occurs is believed torange between tens and hundreds of feet.

The earth's gravitation field varies between a low of about 978 gals atthe equator to about 983 gals at the poles with gradients characterizedin Eotvos units, where one Eotvos unit equals 10⁻⁹sec⁻². For anidealized homogeneous sphere, an equipotential surface outside of thesphere is also spherical. However, density inhomogeneities in the spheregive rise to an equipotential surface that is not spherical; for such asurface, the curvature of any point is different in differentdirections. The two directions along which the curvature is maximum andminimum are termed the principal directions; the difference in curvaturealong these two direction is termed the differential curvature, asexplained more fully below. In the context of the earth, localvariations in gravity are caused by deviations in the surface of theearth from a geometric sphere, surface geology, water tides, atmospherictides, and the change in relative position of the earth, the moon, andthe sun. For any relatively small volume unit in free space, anidealized gravity field can be viewed as a set of unidirectional fieldlines aligned along the local vertical and having zero magnitude in thex,y directions. In the event a mass is placed within that volume unit,the gravity field will be perturbed. For example and as shown in FIG. 5,a dense cylindrically shaped mass M having hemispheroidal ends and afinite length along a major axis located at the center of an arbitraryvolume unit will perturb the local gravity field within that volume unitby causing those field lines closest to the mass M to curve toward themass M and the field lines next removed from the nearest field lines tocurve toward the mass M somewhat less.

For any observation point within an arbitrary volume unit, the gravityfield at that observation point can be resolved into x,y,z components ofwhich the z vector will have the largest magnitude and the x,y vectorswill have respective magnitudes that are a function of the location ofthat observation point relative to the perturbing mass M. Forobservation points in a plane above or below the mass M in FIG. 5, thevector information at that observation point will provide declination orinclination information as the perturbation of the field. In the contextof the example of FIG. 5A, a sufficient number of observations in aplane above the mass M (or a plane below the mass M) will create a dataset from which one or more isopotential surfaces can be obtained thatgraphically define the perturbation in the gravity field caused by theintroduction of the mass M.

In general, the gravity field along the z axis can be measured byuniaxis gravimeters of which a common type uses lasers and ahigh-precision clock to time a mass falling between two verticallyspaced points in an evacuated space. Gradiometers, as distinguished fromgravimeters, measure the curvature gradients (or differential curvatureor ellipticity of the gravity equipotential surfaces), horizontalgradients (or the rate of change of the increase of gravity in thehorizontal direction), or vertical gradients (or the rate of increase ofgravity in the vertical direction). Various processes and instrumentshave been developed to measure the gravity gradient. These processes andinstruments include the lateral deviation of a mass suspended from astring (Bouguer's method) and the torsional twist exerted on ahorizontally suspended beam carrying unequal masses at each end(Cavendish and Eotvos beams). Contemporary gravity gradiometers utilizeforce-restoring accelerometers to measure the lateral x,y components ofthe gravity gradient. In general and in its simplest form, anaccelerometer utilizes a mass suspended at the end of a yieldable beam.Any deviation of the position of the mass from a null position caused byan acceleration experienced by the mass is detected and the massrestored to its null position by a magnetic field applied by a restoringcoil. The current flow in the restoring coil is proportional to theacceleration experienced by the mass.

Some modern gravity gradiometers utilize plural pairs of accelerometersthat are moved at a constant velocity along an orbital path about anaxis. Information from each accelerometer at any angular position in theorbit provides information as to the lateral acceleration experienced bythe acceleration. In the context of FIG. 5A, an accelerometer moving ata constant angular velocity about the orbital path in the observationplane above the mass M will experience positive and negativeaccelerations in the x,y directions and output a sinusoidal waveformthat is modulated with the gravity anomaly information in thatobservation plane. Where the observation plane is normal to the localvertical, the output of the accelerometer does not contain a componentrepresentative of the z axis. Conversely and as explained below in thecontext of the preferred test protocol, if the accelerometer is in anobservation plane that is tilted relative to the field lines, the outputof the accelerometer will also be modulated with z axis information.

A gravity gradiometer suitable for the present invention includes agravity gradient instrument (GGI) sold by the Lockheed Martincorporation (Buffalo N.Y. USA); the Lockheed Martin GGI, the basicstructure of which is shown in FIG. 6, is preferred in the context ofthe present invention. The basic structure and operation of the LockheedMartin GGI is described in U.S. Pat. No. 5,357,802 issued Oct. 25, 1994to Hofmeyer and Affleck and entitled “Rotating AccelerometerGradiometer,” the disclosure of which is incorporated herein byreference.

As shown in FIGS. 6 and 7, the GGI includes eight accelerometers 100mounted at a common radius and equispaced about the periphery of a rotorassembly 102 that is rotated at a constant and controlled angularvelocity about a spin axis A_(x). The rotor assembly 102 includes therotor 104 carried on a support shaft 106 for rotation therewith. Therotor assembly 102 is rotatably mounted in ball bearings 108 and, inturn, carried in a vibration-isolating flex-mount assembly 110.Processing electronics 112 are mounted on the rotor 104 adjacent eachaccelerometer 100 for processing the output signal therefrom asexplained below in the context of FIG. 7. An inner housing 114 containsthe rotor assembly 102 and is designed to rotate with the rotor assembly102. An outer housing 116 contains the interior components and includesone or more heaters 118 designed to operate the instrument at somecontrolled temperature above ambient (i.e., about 115° F.) and alsoincludes a magnetic field shield 120. A slip ring assembly 122 at theupper end of the mounting shaft 106 provides the electrical/signalinterface with the rotor assembly 102 and the active devices thereon. Ashaft encoder 124 at the lower end of the mounting shaft 106 cooperateswith an encoder pick off 126 to provide rotary position information. Theoutput of the encoder pick off 126 is provided to a computer and speedcontroller, which, in turn controls a drive motor 128 at the upper endof the unit to provide a controlled rotary velocity.

Each accelerometer 100 provides a sinusoidally varying analog outputthat is a function of the acceleration experienced by each accelerometeras the accelerometer orbits the spin axis. For a gradiometer having itsspin axis aligned along the field lines in an ideally uniform andunperturbed gravity field, each accelerometer experiences the sameacceleration forces as its proceeds along its orbital path. However,where the local gravity field is perturbed by the presence of one ormore masses and/or the spin axis is tilted relative to the localvertical field lines, each accelerometer will experience differentaccelerations throughout its orbit. The quantitative output of eachaccelerometer, coupled with it rotary position, provides informationrelated to the local gravity gradients.

At any observation point, the gravity gradient is a second orderderivative of the gravity potential scaler Γ and is represented by asecond-order nine-component symmetric tensor Γ_(ij) as follows:$\begin{matrix}{\Gamma_{i,j} = \begin{matrix}\Gamma_{x,x} & \Gamma_{x,y} & \Gamma_{x,z} \\\Gamma_{y,x} & \Gamma_{y,y} & \Gamma_{y,z} \\\Gamma_{z,x} & \Gamma_{z,y} & \Gamma_{z,z}\end{matrix}} & {{EQ}.\quad 1}\end{matrix}$

The components Γ_(x,z)and Γ_(y,z) are approximately equal to thevariation of the force of gravity along the x and y directions,respectively, and are known as the horizontal gradient components, andΓ_(z,z) is known as the vertical gradient of gravity. The differentialcurvature is related to Γ_(x,x), Γ_(y,y), and Γ_(x,y) as follows:

[(Γ_(x,x)−Γ_(y,y))²+4(Γ_(x,y)) ²]^(½) /F  EQ. 2

where F is the force of gravity.

In addition to the differential curvature of Eq. 2, a curvature vectorwhose magnitude equal the differential curvature is also defined by thevalue λ as follows:

λ=−½ tan⁻¹[2Γ_(x,y)/(Γ_(y,y)−Γ_(x,x))]  EQ. 3

where λ is the angle of the differential curvature vector relative tothe x axis.

As is known, the diagonal elements are scalar invariant and conform tothe Laplacian relationship:

0=Γ_(x,x)+Γ_(y,y)+Γ_(z,z)  EQ. 4

from which it follows:

Γ_(z,z)=−(Γ_(x,x)+Γ_(y,y))  EQ. 5

Additionally, three pairs of the nine elements are symmetrically equal,i.e., Γ_(x,z)=Γ_(z,x), Γ_(y,x)=Γ_(z,y), and, lastly, Γ_(x,y)=Γ_(y,x) sothat the tensor is characterized by five independent components.

The gradients Γ_(y,y)−Γ_(x,x) and 2Γ_(x,y) in Eq. 1 are the twocurvature gradient components, while Γ_(x,z) and Γ_(y,x) are the twohorizontal gradient components; Γ_(z,z) is the vertical gradientcomponent.

The output of the accelerometers is processed in accordance with theblock diagram of FIG. 7; processing may be effected by discretesolid-state functional devices, by software or firmware controlledmicroprocessors or computers, by an application specific integratedcircuit (ASIC), or by any combination thereof.

As shown, the pre-processed outputs of the eight accelerometers 100 ofthe gravity gradient instrument GGI of FIG. 6 are divided into twogroups ‘A’ and ‘B’ of four with each group sub-divided to two sub-groupsi.e., (A1,A2), (A3,A4), (B1,B2), and (B3,B4).

The accelerometer outputs A1,A2 are presented to the inputs of summingdevice SUM(A1+A2) and the outputs A3,A4 are likewise presented a summingdevice SUM(A3+A4). The summed outputs of the devices SUM(A1+A2) andSUM(A3+A4) are presented to a subtractor SUB-A. In a similar manner, theaccelerometer outputs B1,B2 are presented to the inputs of summingdevice SUM(B1+B2) and outputs B3,B4 are likewise presented a summingdevice SUM(B3+B4). The summed outputs of the devices SUM(B1+B2) andSUM(B3+B4) are presented to a subtractor SUB-B. The summation of thesignals of the diametrically opposed accelerometers 100 effectivelycancels the component of acceleration due to any displacement in therotor assembly in the XY plane.

The differencing operation in the subtraction circuits SUB-A and SUB-Bremoves the effect of any angular acceleration of the rotor assemblythat may occur in response to angular speed correction signals sent tothe motor by its speed controller.

A set of four demodulators demodulate the outputs of the subtractiondevices SUB-A and SUB-B in response to inphase and quadrature referencesignals at twice the rotational frequency of the rotor assembly and by areference signal source. The reference signal source can include aphase-locked loop oscillator locked in phase to revolutions of the rotorassembly 102 in response to the output of the encoder pickoff 126. Theinphase reference signal sin 2 ΩT is applied to demodulators DEMOD-SAand DEMOD-SB connected, respectively, to the output terminals of thesubtraction circuits SUB-A and SUB-B. In a similar manner, thequadrature reference signal cos 2 ΩT connected to demodulators DEMOD-CAand DEMOD-CB, also connected, respectively, to the output terminals ofthe subtraction circuits SUB-A and SUB-B. The output signals of the fourdemodulators DEMOD-SA, DEMOD-SB, DEMOD-CA, and DEMOD-CB take the form ofsquared values of sine and cosine signals. More specifically, DEMOD-SAoutputs a value 2R(Γ_(xx)−Γ_(yy))sin²2 Ωt and the associated 4 Ωt terms,the demodulator DEMOD-CA outputs a value 4RΓ_(xy) cos²2 Ωt and the 4 Ωtterms, the demodulator DEMOD-SB output a value minus 4RΓ_(xy)sin²2 Ωtand the 4 Ωt terms, and, lastly, the demodulator DEMOD-CB outputs avalue 2R(Γ_(xx)−Γ_(yy))cos²2 Ωt and the 4 Ωt terms. The term 2R is thedistance between opposing accelerometer sets, i.e., the distance betweenaccelerometer pair A1 and A2.

Summing circuit SUM-A accepts the output signal of the demodulatorsDEMOD-SA, and DEMOD-CB and provides the summed output though a low-passfilter LP-A. In a similar manner, summing circuit SUM-B accepts theoutput signal of the demodulators DEMOD-SB and DEMOD-CA and provides thesummed output though a low-pass filter LP-B.

The output signals of the demodulators DEMOD-SA, DEMOD-SB, DEMOD-CA, andDEMOD-CB include higher frequency components in terms of frequenciesequal to four times the rotational frequency of the rotor assembly. Thegradient data, apart from a scale factor, is given by both the squaredsinusoid and the squared cosinusoid components of the demodulatedsignals. These components sum together at the summing circuits SUM-A andSUM-B to provide a DC (direct current) value of the gradient data, alongwith the higher-frequency components. The low-pass filters LP-A and LP-Bfunction, respectively, to filter the output signals of the summingcircuits SUM-A and SUM-B and attenuate the high-frequency components soas to provide the desired DC components of the signals representing thegradient data. The gradient data is outputted from the low-pass filterLP-A in the form of an expression that includes the term2R(Γ_(xx)−Γ_(yy)), and from the low-pass filter LP-B in the form of theexpression 4R(Γ_(xy)).

Dividing the outputs 2R(Γ_(xx)−Γ_(yy)) and 4R(Γ_(xy)) by 2R yields tworesults, (Γ_(xx)−Γ_(yy)) and 2(Γ_(xy)), that define the curvaturevector; the magnitude of the curvature vector is known as the“differential curvature” or the “horizontal directing tendency” and isthe square root of the sum of (Γ_(xx)−Γ_(yy))² and (2Γxy)².

The direction A of the curvature vector with respect to the X-axis isrepresented by:

λ=−½ tan⁻¹(2Γxy/(Γyy−Γxx))

The description above in relationship to FIG. 7 presents the function ofthe GGI when the sensitive axes of the accelerometers are in the lanenormal to the vertical. In this orientation, the instrument is optimizedfor sensing the x,y components of the gravity gradient. However, anumber of errors can be introduced into the signal output as aconsequence of the structure of the instrument itself. In the design ofthe GGI, the mass is sought to be distributed in a uniform and symmetricmanner about the spin axis A_(x). Because the GGI uses discrete devices,some mass asymetricities exit about the spin axis. Additionally, the GGIis not mass-symmetric above and below the plane of the rotor 104. Whilethe mass asymmetry is small, the asymmetry is physically close to theaccelerometers and is believed to have an influence as an errorcomponent.

In accordance with one feature of the present invention and as explainedbelow in relation to the test protocol of FIG. 10, the GGI is operatedin at least two orthogonally spaced headings (i.e., 90 degrees). Sincethe instrument-specific bias and instrument-specific gradient errors are“fixed” to the instrument itself and its connected structures, rotatingthe GGI about its spin axis to the two orthogonal headings will notchange the values of the instrument-specific bias andinstrument-specific gradient errors while, concurrently, the sign of themeasured earth's fixed gradients are reversed. By averaging thedifferences between the measurement sets at two orthogonal headings,absolute values of the earth's curvature gradients can be obtained sincethe instrument-specific bias and instrument-specific gradients willcancel out.

As explained in the mathematical presentation of FIG. 8, the primaryoutput of the GGI can be characterized as an “in-line” I/L component andthe secondary output can be characterized as a “cross” CR component. Inthe context of the functional block diagram of FIG. 7, the in-line andcross components can be assigned as shown in EQ. 1 and EQ. 2 in FIG. 8.The x axis of the GGI can be aligned, e.g., north, and, using the EulerAngle Sequence, the curvature gradients measured by the instrument x,yframe can be expressed as a function of the fixed curvature gradients ofthe earth in the north (n) and east (e) context as represented by EQ. 3and EQ. 4 of FIG. 8. The GGI in-line outputs at a north azimuth heading(0 degrees) is represented in FIG. 8 by I/L(H=0°) and for the orthogonalmeasurement by I/L(H=90°). In a similar manner, the GGI cross outputs ata north and east heading are represented by CR(H=0°) and for theorthogonal measurement by CR(H=90°) so that bias-free values of thecurvature gradient can be obtained from EQ. 5-EQ. 9 in FIG. 8.

As explained below in relationship of FIGS. 10A and 10B, the GGI isoperated during the test protocol with its spin axis ‘tilted’ at a smallpositive angle and a small negative angle relative to the horizontalplane to generate a horizontal component of the gravity to excite thefeedback compensation control loops in the GGI and allow for calibrationof the accelerometer scale factors. However, the tilted spin axiscouples the earth's horizontal gravity gradients into the curvaturemeasurements of the GGI. Obtaining measurements with the GGI tilted at asmall angle above the horizontal and at the small angle below thehorizontal, in connection with measurements made at two azimuthsheadings that are 90 degrees apart, will yield measurements that doublethe desired curvature gradients and cancel out the undesired horizontalgradients.

The GGI includes orthogonal roll and pitch axes of which the roll axisis kept horizontal in the local x,y plane while the instrument isrotated about its roll axis to pitch the instrument up or down relativeto the local horizontal plane. The term I/L indicates a line that is inthe x,y plane of the GGI that can be aligned at an azimuth heading whilethe instrument x,y plane is pitched (tilted) at some small anglerelative to the local x,y plane. The secondary gradiometer instrumentoutput is the ‘cross’ term CR as explained above in relationship to EQ.1 and 2 of FIG. 8. In the context of the mathematical presentation ofFIG. 9, the I/L and the CR gradients measured by the GGI in its x,yframe can be expressed as a function of the earth's tensor gradientcomponents in the geodetic north, east, and down (n, e, d) frame ofreference. The direction cosine matrix (DCM) that transforms a north,east, and down geodetic frame to the x,y,z, instrument frame at aheading angle H and a pitch angle P represented in EQ. 1 of FIG. 9. TheI/L and the CR GGI outputs are related to the geodetic gradients asrepresented in EQ. 2 and 3 of FIG. 9 where the terms “error (I/L)” and“error (CR)” include instrument self-bias and all instrument-specificgradient errors. As shown in EQ. 4 and EQ. 5, the sum of the up and downmeasurement are indicated where the superscript “U” indicates an “up”pitch, and the superscript “D” indicates a “down” pitch with EQ. 6 andEQ. 7 showing the relationship to the geodetic gradients. By applyingthe measurements at H=0 degrees and H=90 degrees, and computing the sumof the in-line and cross values result yields Eq. 8 and Eq. 9 toestimate the curvature gradients Γee−Γnn and 2Γne without coupling fromthe Γnd and the Γed horizontal gradients and the Γdd vertical gradientwith these values free of bias and instrument-specific self-gradienterrors. EQ. 10 and Eq. 11 represent the difference between the “up” andthe “down” I/L and the CR measurements while EQ. 12 and EQ. 13 providethe estimate of the horizontal gradients from measurements made 180degrees apart.

In accordance with the test protocol of the present invention and asshown in FIGS. 10A and 10B, a number of measurement stations n areestablished on the oil field. Each measurement station can take the formof an area of cleared earth or, more preferably, an asphalt or cementpad. It is important that the station location be fixed for the periodof the first and subsequent tests. The measurement stations preferablycan take the form of a rectangular array of observation positions, apolar array of observation positions, or a mix thereof includingobservation stations that do not follow a pre-assigned pattern and canbe considered as randomly placed within the field under observation. Forexample and in the context of FIGS. 2 and 3, the measurement positionscan correspond to the position of the row and column block numbersshown.

The GGI is preferably mounted on a small, wheeled cart that can be movedfrom station to station as the test proceeds. Depending upon thedistance between observation stations, the GGI can be transported, forexample, by a wheeled or other vehicle. If desired, the GGI can bemounted on a wheeled vehicle and driven from station to station and themeasurements taken from the vehicle. The mobile cart is preferred,however, as the use of the cart eliminates gravitation anomaliesintroduced by the wheeled vehicle from the data set. At each of themeasurement stations, the cart is elevated on elevation control jacks.

As shown in the flow diagram of FIG. 10A, the system is initialized andthe variables m and n set equal to 1; n being representative of thenumber of pre-established measurement stations where the maximum numberof measurement stations is N(max) and m representing the number of datasets to be taken over time where the maximum number is M(max).

The GGI is positioned at the first measurement station and, prior to theinitiation of data taking, all objects having a mass sufficient toaffect the measurements (transport vehicle(s), power sources, localcomputer control, personnel, etc.) are moved a sufficient distance awayfrom the instrument to minimize any adverse effects on the instrumentfrom those objects. In general, each measurement station is preferablynot located next to man-made fixed-in-place static structures tominimize large signals that are not related to the locations of theboundary interface.

Thereafter, the GGI is initialized and the spin axis is inclined to somepre-selected tilt angle (i.e., plus about 0.9 degree in the case of thepresent invention) sufficient to provide a z axis response in theaccelerometers and the instrument aligned at an azimuth heading of zerodegrees. As explained above in relationship to FIG. 9, the ‘tilting’ ofthe rotor assembly at some angle sufficient for the eight accelerometersto sense the gravity vector allows the instrument to observe the outputof each accelerometer for that gravity value, identify the scale factorof each accelerometer, the differences in the scale factors between theaccelerometers, and identify an adjustment value so that allaccelerometers provide an identical apparent output. As shown in theflow diagram of FIG. 10A, the instrument is also subsequently subject toa tilt at an opposite angle from the first so that cross-couplings fromhorizontal gradients can be eliminated. Thus, measurements taken at thefirst tilt angle includes instrument bias and, in a similar manner,measurements taken at the opposite tilt angle likewise containinstrument bias errors; the measurements for both tilt angles can thenbe averaged to cancel the bias error.

The GGI then takes data at the observation station for some period oftime sufficient to insure minimization of error sources; in the case ofthe preferred GGI, a data taking interval on the order of severalminutes (i.e., about five minutes) at each heading is consideredadequate.

Thereafter, the instrument is declined to the its opposite angle (i.e.,minus about 0.9 degree in the case of the present invention) and thedata taking step repeated at the initial azimuth. Once data taking iscompleted at the initial azimuth heading for both the tilted up andtilted down attitudes, the instrument is rotated in azimuth byincremented ninety degrees and the tilted up and tilted down data takingsteps repeated. The tilted up and tilted down data taking need only beconducted at two azimuth heading; however, the tilted up and tilted downdata taking can be repeated at more azimuth headings if desired, toincrease the accuracy of the data taking. Rotation of the instrument tothe new heading includes the instrument itself, its cart, and anyassociated structures, including any environmental enclosure. Therotation of the structures associated with the operation of theinstrument itself assists in minimizing error sources. As explainedabove in relationship to FIG. 8, azimuth slewing functions to provideinformation necessary to remove error sources associated with the massdissymmetry of the instrument itself and its immediate surrounding. Thissequence proceeds until data is taken in at least three orthogonalazimuth headings; however, in the case of the preferred embodiment, datais taken at 0, 90, 180, 270, and then again at 0 degrees. If additionalinformation is desired, data taking steps can be repeated at the variousheadings.

As explained in more detail above, the taking of data at differentazimuth headings and at different tilt angles is designed to minimizeerror sources and effectively increase the sensitivity of theinstrument.

Thereafter, n is incremented by one and the GGI moved to the nextsuccessive measurement station and the sequence at that stationrepeated.

When data is taken at each of the n measurement stations (i.e.,n=N(max), the first data set is completed. In accordance with thepresent invention, a period of time (measured in weeks, months, oryears) is allowed to lapse during which the oil field undergoescontinuous or non-continuous pressurization by the injected driveoutfluid to cause migration of the interface between the driveout fluid andthe hydrocarbons to be recovered. After the inter-test period haselapsed, the test sequence of FIG. 10A is repeated to yield another setof data characterized as the second data set. As can be appreciated,third, fourth and subsequent tests can be undertaken after suitableinter-test time periods have elapsed to yield third, fourth andsubsequent data sets. In practice, two successive data sets (i.e.,M(max)=2) are sufficient to provide usable data.

Each data set includes information as to the gravity gradient over thefield including the effect of sub-surface geology, variations consequentto the terrain, and man-made fixed-in-place static structures includingderricks, pipelines, pumps, motors, etc. that typically occupy anoilfield. In addition, that data set will include information as to theeffect on the gravity gradient of the interface between the driveoutfluid and the hydrocarbons undergoing displacement. However, there is nonon-conjectural way that the location of the interface can be accuratelydetermined from a single data set. As in the case of the first data set,second and subsequent data sets likewise include information as to theeffect on the gravity gradient of the geology, terrain, and man-madestructures and the interface at its new location. Thus, information asto the geology, terrain, and man-made structures will representrelatively invariant common data or common mode signal informationbetween each data set while the information as to the transient-in-timeinterface will not be common to the various data sets.

Error sources that can adversely affect accuracy can include geologicmovements, such as compaction of the oil reservoir and movement of thewater table.

In order to process the first and second (and/or subsequent data sets)and as an initial step, a theoretical model of the relationship of thegravity gradient of the strata below the hydrocarbon reservoir ofinterest is developed. For any hydrocarbon reservoir undergoingsecondary recovery, the probability is that a body of geophysical data,including a reservoir model, is available from prior acoustic surveys,borehole data logging, core samples, analysis of the output of testwells, and a knowledge of the presence or absence of (and changesthereof) the driveout fluid in the output of the production wells. Ifdesired, the known geophysical data can be combined with availablegravity gradient data obtained in accordance with the system and methodof the present invention. More specifically, the gradient data can be‘best-fitted’ to the geophysical data to provide a forward model of thereservoir and/or the gradient data can be similarly ‘best-fitted’ to thegeophysical data using inversion techniques to obtain the best model ofthe reservoir and the model boundary between the driveout fluid and thehydrocarbon to be recovered.

In order to obtain the sub-surface density information, either forwardmodeling methods (also known as the indirect method) or direct methodscan be used. Forward modeling methods start with existing knowledgeabout the reservoir layers in which injection is being carried out andassumes changes in the saturation levels of the different fluids,incorporating knowledge gained from other geophysical measurements(e.g., seismic) and other oil field observations, such as pressures andtemperatures changes in the observation wells. From this starting modelcalculations of the time-lapse gradients can be made. For this purposed,the forward modelling method of Talwani, “Computation with the help of adigital computer of magnetic anomalies caused by bodies of arbitraryshape” in Geophysics, Vol. 30, No. 5, pps 797-817 (1965) can beutilized. The calculated values are compared with observed values of thetime-lapse gradient, and the starting model iteratively modified so thatthe calculated values fit the observed values. Examination of thesaturation values in the final model yield the position of the frontbetween the driveout fluid and the hydrocarbons undergoing displacement.

With direct methods, existing knowledge about the reservoir is used asconstraints and the observed data inverted to yield sub-surface densitychanges, which as for the forward modeling methods are related to fluidsaturation changes.

Once the time-lapsed (i.e., 4D) gradient data is obtained, numerouscomputerized techniques are available to determine the change in thesub-surface density distributions (strata morphology) over the timeperiod. Direct methods of using the gradient data to estimate densitydistributions fall into the category of linear problems and directmethods that determine boundary perturbations for constant densitybodies fall into the category of nonlinerar problems as described by D.W. Vasco in “Resolution and Variance Operators of Gravity and GravityGradiometry” published in Geophysics, vol. 54, no. 7, (July 1989) pps.889-899. The Vasco solution linearizes relations between prisms (of massdensity or changes in density) and their associated gravity gradientsand solves the inversion iteratively, using generalized inverses. Directmethods also include those described by S. K. Reamer and J. F. Fergusonin “Regularized two-dimensional Fourier gravity inversion method withapplication to the Silent Canyon caldera, Nevada” published inGeophysics, vol. 54, No. 4 (April 1989) pps. 486-496 and thewavelet-Galerkin techniques described in the above-incorporated U.S.Provisional application 60/099,937 filed Sep. 11, 1998. In general andfor the Vasco technique, constraints such as a layer thickness greaterthan or equal to zero or all the boundaries to lie in the sub-surfacemay be included; other constraints include reasonable ranges in densityafter M. Cuer and R. Bayer as described in “Fortran Routines for LinearInverse Problems” published in Geophysics, vol. 45, No. 11 (November1980), pps. 1706-1719.

The initial model will be improved with increasing data and can be onlythe best known estimate at that time. The model, forward or inverse, isthen perturbed analytically to determine the relationship betweenchanges in the gravity gradient to changes in the strata morphology.Indirect methods for perturbing a starting or initial forward modelinclude the “Directed Monte Carlo methods of Simulated Annealing andGenetic Algorithms [“Global Optimization Method in GeophysicalInversion,” by M. Sen and P. L. Stoffa, Elsevler, Amsterdam, 1995].

Thereafter, the actual gravity gradient (of which a representativegraphical representation for Γxz and Γxx is shown in FIG. 11) iscompared with that predicted by the theoretical model to developsuccessive model iterations that converge with successively smallerdifferences in the comparisons. As additional data measurements aretaken, as shown in the test sequences of FIG. 10A and 10B, the model issuccessively refined. Before each model refinement, the measured dataare processed to eliminate known and statistically estimated errorsources including the effects of geologic “noise”.

With sufficient data measurements, it is possible for the computer dataprocessor to create a computer-displayed animation of the movement andmorphology of the boundary interface with time for display on a computermonitor or similar display device. The processed data provided by thedisplay yields information as to the boundary between the driveout fluidand the to-be-recovered hydrocarbon. Thereafter, the movement of theboundary and the rates of movement can be graphically printed or plottedfor use by the oil field manager, who can control the injection wells interms of pressure and quantity to use the morphology of the boundary insuch a way as to maximize hydrocarbon recovery at the lowest possiblesecondary recovery cost. The illustration of hydrocarbon boundaries andtheir changes can be also used by the oil field manager for theidentification of possible theft zones as suggested in blocks 22 and 23of FIG. 3. Providing the oil field manager with this pictorialrepresentation of the developing situation enables him to apply hisexpertise to evaluate, correct, and compensate for changing conditionsand to maintain or to increase field production.

The present invention advantageously provides a system and process forsecondary oil recovery by which the cost of recovery can be reducedand/or the quantity of hydrocarbon recovered can be increased. Thepresent invention is likewise well suited for use in detecting themigration of sub-surface fluids including, for example, polluted and/ortoxic fluid fronts. While an accelerometer-type gradiometer is shown asthe preferred instrument for detecting the gravity gradient, otherdevices capable of measuring or otherwise ascertaining the local gravitygradient are likewise suitable. Other devices include paired gravimetersof the type that use falling masses in an evacuated space with theacceleration of the falling mass measured with a laser beam andhigh-accuracy clocks and gravity sensing instruments that usesuperconducting sensors.

As will be apparent to those skilled in the art, various changes andmodifications may be made to the illustrated system and process forsecondary oil recovery of the present invention without departing fromthe spirit and scope of the invention as determined in the appendedclaims and their legal equivalent.

What is claimed is:
 1. A process for controlling fluid hydrocarbonproduction from a sub-surface hydrocarbon reservoir undergoing secondaryrecovery by injection of a driveout fluid therein and from which fluidhydrocarbons are removed in response to the driveout fluid injection,comprising: establishing a plurality of measurement positions for themeasurement of the local gravity gradient; performing a first assay ofthe gravity gradient above the reservoir; performing at least a secondassay of the gravity gradient above the reservoir, said first and secondassay separated by a period of time; identifying the position of theinterface between the driveout fluid and the fluid hydrocarbons fromdata between the first and second assays; and controlling the injectionof the driveout fluid to control removal of the hydrocarbons from thereservoir.
 2. The process of claim 1, wherein said first assay isperformed by measuring the gravity gradient at a plurality ofmeasurement positions.
 3. The process of claim 1, wherein said secondassay is performed by measuring the gravity gradient at a plurality ofmeasurement positions.
 4. The process of claim 1, wherein said firstassay and second assay are each performed by measuring the gravitygradient at a plurality of common measurement positions.
 5. The processof claim 1, further comprising at least a third assay of the gravitygradient above the reservoir, said second and third assays separated bya period of time and thereafter identifying the position of theinterface between the driveout fluid and the fluid hydrocarbons fromdata between the first and third assays, the second and third assays, orthe first, second, and third assays.
 6. The process of claim 1, furthercomprising combining known geophysical data relating to the reservoirwith at least one of the gradient assays to obtain a combinedgeophysical/gravity gradient model of the reservoir.
 7. The process ofclaim 6, wherein said combining step comprises combining the gravitygradient assay with the known geophysical data by forward modelling. 8.The process of claim 7, wherein said combining step comprises combiningthe gravity gradient assay with the known geophysical data by inversionusing computerized techniques.
 9. The process of claim 1, wherein saidcontrolling step comprises at least controlling one of the pressure,temperature, volume, and location within the reservoir of the injecteddriveout fluid.
 10. A process for monitoring an interface between adriveout fluid and fluid hydrocarbons in a sub-surface reservoirundergoing secondary recovery by injection of the driveout fluid thereinand from which fluid hydrocarbons are removed at least in response tothe injection of the driveout fluid, comprising: performing a first setof measurements of the gravity gradient at a plurality of measurementpositions; performing at least a second set measurements of gravitygradient at each of the measurement positions, said first and secondsets of measurements separated by a period of time; identifying theposition of the interface between the driveout fluid and the fluidhydrocarbons from difference data between the first and second assays;and displaying position of the interface between the driveout fluid andthe fluid hydrocarbons.
 11. The process of claim 10, further comprisingperforming at least a third measurement of the gravity gradient abovethe reservoir, said second and third measurements of the gravitygradient separated by a period of time and thereafter identifying theposition of the interface between the driveout fluid and the fluidhydrocarbons from difference data between the first and thirdmeasurements, the second and third measurements, or the first, second,and third measurements.
 12. The process of claim 10, further comprisingcombining known geophysical data relating to reservoir with at least oneof the gradient measurements to obtain a combined geophysical/gravitygradient model of the reservoir.
 13. The process of claim 12, whereinsaid combining step comprises combining the gravity gradient measurementwith the known geophysical data by forward modelling.
 14. The process ofclaim 12, wherein said combining step comprises combining the gravitygradient measurement with the known geophysical data by inversion. 15.The process of claim 10, wherein said measurements are performed by agravity gradiometer.
 16. The process of claim 11, wherein saidmeasurements are performed by a gravity gradiometer of the typeutilizing accelerometers.
 17. A system for monitoring the interfacebetween a driveout fluid and a fluid hydrocarbons in a sub-surfacereservoir undergoing secondary recovery by injection of a driveout fluidtherein and from which fluid hydrocarbons are removed at least inresponse to the injection of the driveout fluid, said system comprising:means for establishing a plurality of measurement positions for themeasurement of the local gravity gradient above the reservoir; a gravitygradient measuring instrument moved to at least some of said measurementpositions for measuring the gravity gradient at each of said measurementpositions to obtain a first set of gravity gradient data and formovement, at a time subsequent to the time the first set of data wasobtained, to at least some of said measurements to obtain a second setof gravity gradient data; a data processor for processing the first andsecond set of data to identify the position of the interface between thedriveout fluid and the fluid hydrocarbon from difference data betweenthe first and second sets of data, and a display device for displayingthe so-identified position of the interface.
 18. The system of claim 17,wherein said measurements are performed by a gravity gradiometer of thetype utilizing accelerometers.
 19. A process for monitoring theinterface between a first fluid and a second fluid in a sub-surfacevolume in which one of said first and second fluids displaces the otherof said first and second fluids with time, comprising: establishing aplurality of measurement positions for the measurement of the localgravity gradient; performing a first set of measurements of the gravitygradient at the surface above the sub-surface volume; performing atleast a second set of measurements of gravity gradient at the surfaceabove the sub-surface volume, said first and second measurementsseparated by a period of time; identifying the position of the interfacebetween the first fluid and the second fluid from at least differencedata between the first and second sets of measurements; and displayingthe position of the interface between the first and second fluids. 20.The process of claim 19, further comprising performing at least a thirdmeasurement of the gravity gradient above the sub-surface volume, saidsecond and third measurements of the gravity gradient separated by aperiod of time and thereafter identifying the position of the interfacebetween the first and second fluids from at least difference databetween the first and third measurements, the second and thirdmeasurements, or the first, second, and third measurements.
 21. Aprocess for monitoring the sub-surface migration of at least a firstfluid in a sub-surface volume in which the first fluid migrates in thesub-surface volume with time, comprising; establishing a plurality ofmeasurement positions for the measurement of the local gravity gradient;performing a first set of measurements of the gravity gradient at thesurface above the sub-surface volume; performing at least a second setof measurements of gravity gradient at the surface above the sub-surfacevolume, said first and second measurements separated by a period oftime; identifying the position of the edge of the at least first fluidfrom at least difference data between the first and second sets ofmeasurements; and displaying the position of the edge of the at leastfirst fluid.
 22. The process of claim 21, further comprising performingat least a third measurement of the gravity gradient above thesub-surface volume, said second and third measurements of the gravitygradient separated by a period of time and thereafter identifying theedge of the at least one fluid from at least difference data between thefirst and third measurements, the second and third measurements, or thefirst, second, and third measurements.